Steerable well drilling system

ABSTRACT

A steerable dual drilling bit having an outer reamer bit defining a central opening and having an inner core removal bit being rotatably driven by a mud motor that is supported within a tubular housing by the outer reamer bit. The dual drilling bit is capable of being threaded to the bit box of a rotary drill string or a straight or bent housing drilling system. The dual drilling mechanism is of sufficiently limited length that it is capable is being efficiently steered for directional drilling. The reamer and core removal bits are arranged to continuously cut away a formation core and to employ the core for rotational stabilization of the reamer bit during drilling.

RELATED PROVISIONAL APPLICATION

Applicant hereby claims the benefit of U.S. Provisional PatentApplication No. 61/886,498, filed on 3 Oct. 2013 by Edwin J. Broussard,Jr. and entitled “Steerable Well Drilling System”, which provisionalapplication is incorporated herein by reference for all purposes.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates generally to well drilling systems andparticularly to well drilling mechanisms having a reamer bit defining acentral opening within which a formation core is permitted to enter asthe reamer bit progresses into the formation. The well drilling systemof the present invention has a core removal bit that is located withinthe reamer bit and is independently rotated for continuously cuttingaway the core of formation material that is not cut away by the rotatingcutters of the reamer. The present invention also concerns dual drillbit well drilling systems having a housing to which is mounted a reamerbit and having a mud motor mounted to the reamer bit and positionedwithin the housing and disposed in driving relation with a core removalbit that is rotatable within the reamer bit for continuous core removal.Both the reamer bit and core removal bit preferably incorporatepolycrystalline diamond (PDC) formation cutting elements that aresupported by a matrix material but may also incorporate hardened metalcutting elements or rotary cone cutting elements, if desired. Evenfurther, the present invention concerns a wellbore drilling systemhaving a reamer that leaves a central core of formation material duringdrilling and having a smaller, mud motor driven core removal bit that iteither located concentrically or eccentrically with respect to thereamer bit for efficiently removing the remaining core material. Thepresent invention particularly concerns a method for well drilling inconsolidated formations by mounting a short straight or directional mudmotor powered dual rotary bit well drilling mechanism, typically havinga length in the range of about 4′, below the bend structure of a typicalbent housing well drilling mechanism and selectively orienting the benthousing and short drilling system for directional steering of thewellbore being drilled.

2. Description of the Prior Art

Dual PDC well drilling systems having an external reamer bit and aninterior mud motor driven core removal bit are disclosed by U.S. Pat.No. 7,562,725 of Edwin J. Broussard, Jr. and Herman J. Schellstede. Areamer bit is mounted to and rotated by a rotary drill string thatextends from a rotary drilling rig at the surface. The core removal bitis rotated by a mud motor that is located within a drilling unit, themud motor being driven by the flow of drilling fluid that is pumpedthrough the drill string from the surface. Another somewhat similardrilling system is disclosed by U.S. Pat. No. 8,201,642 of Steven J.Radford, et al, wherein a reamer bit is rotated in one direction by thedrill string and a concentric bit is located within the reamer bit andis rotated in a counter rotational direction by a downhole motor such asa positive displacement motor (PDM). It is noted that the smallercentrally located bit is located entirely within the outer reamer bit,with its cutting elements engaging the central portion of the formationwithin which the wellbore is being drilled. The drill cuttings of thesmaller bit will tend to build up on the cutting interface of thesmaller bit, thus further interfering with its formation cuttingcapability. Though these types of drilling systems will function andachieve wellbore drilling, typically no provision is made forcontrolling the delivery of drilling fluid for reamer drilling, coreremoval bit drilling, mud motor operation and bearing cooling for themud motor and other components of the drilling system.

During well drilling with a conventional PDC bit, it is known that themost central of the PDC cutter members will be rotated against theformation being drilled at a slower speed as compared with the PDCcutter members that are located further from the center portion of thebit. This difference in formation cutting speed is due to thecircumferential distance each of the PDC cutter members travel duringeach revolution of drill bit rotation. The cutter members at the outerperiphery of a drill bit travel at a greater formation cutting speedthan the cutters near the center of the bit. The slower cutting speed ofthe more centrally located cutters causes inefficient formation cuttingat the central portion of the borehole being drilled, so that thecentral portion of the drill bit cutting face tends to crush, ratherthan cut the formation material, and thus retards the overallpenetration rate of the bit. It is considered desirable therefore, toemploy the benefits of PDC cutter members for rotary well drillingwithout having the well drilling efficiency hampered by inefficientformation cutting at the central portion of a drill bit.

It has been determined that by relieving the central portion of thecutting face of a drill bit, the formation cutting efficiency andpenetration rate of the bit will be significantly enhanced. However,such a drill bit will permit a central formation core to remain. Thiscore must be removed so that it will not interfere with the drillingprocess. According to U.S. Pat. No. 7,562,725 of Edwin J. Broussard andHerman J. Schellstede, a dual PDC drilling system is provided having anouter reamer bit for cutting away a major part of the formation duringdrilling and having an inner core removal bit that is independentlyrotated, such as by means of a mud motor or other rotary power system ofthe drilling mechanism and which functions to continuously andcompletely cut away the remaining central formation core that is not cutaway by the reamer bit. U.S. Pat. No. 8,201,642 discloses a dual bitwell drilling system having a reamer bit and a small centrally locatedbit within the reamer bit that is rotated in a direction that isopposite the rotation of the reamer bit. Another well drilling systemhas been developed which employs a rotary PDC reamer bit for primarydrilling and employs a fixed PDC element at the center of the reamer bitto fracture away or crush the formation core material that is not cutaway by the reamer bit.

PDC drill bits typically drill an oversize wellbore, and thus allow forlateral movement of the drill bit within the formation while drilling.This lateral drill bit movement is undesirable because it causes theresulting borehole to be oversize or out of gauge and will often causethe PDC cutters to be sheared from the bit. Drill bit manufacturersrecognize this potential problem and are known to design the PDC bits tohave a somewhat concave cutting face and rounded towards the outerperiphery. This bit geometry causes wedging of the drill bit into theborehole and thus minimizes the potential for lateral bit movementduring drilling and also minimizes the development of shearing forces onthe PDC cutter members. However, these concave PDC bit designs cause thecutter area of the bits to be increased and thus cause the cost of theresulting bit to also be increased. This increased drill bit cost is acommercial disadvantage to the well drilling industry.

The dual PDC drill bit arrangement of the present invention achievesmore rapid penetration in most hard subsurface formations becausedrilling penetration is not resisted by poor drilling capability of thecentral portion of the bit and by the presence of a formation core thatdevelops between the PDC bit blades and retards penetration movement ofthe bit. The larger the core diameter is and longer it is, (to a point)will significantly stabilize the bit during its drilling rotation andthus minimize the lateral movement that is typically inherent in causingthe drilling of oversize wellbores by PDC drill bits. The faster therate of penetration, the more properly gauged the resulting wellborewill be and the better the bit will be stabilized during its rotationaloperation. With these advantageous features of bit design incorporated,a flatter PDC bit could be built, having less surface cutter area,thereby minimizing the number of PDC cutters that are employed in bitdesigns and minimizing the application of torque force to the drillstring.

SUMMARY OF THE INVENTION

It is a principal feature of the present invention to provide a novelwell drilling system that is adapted for threaded mounting to a bit boxof a drill string or mud motor for straight drilling and is adapted tobe mounted immediately below the bend of a bent housing type mud motorfor directional drilling.

It is another feature of the present invention to provide a novel welldrilling system that is of limited length, the limited lengthcontributing to the capability of the drilling system to be selectivelyoriented for directional steering for drilling a directional well.

It is also another feature of the present invention to provide a novelwell drilling system that may incorporate any of a number of differenttypes of formation cutting elements, such as polycrystalline diamondcutting elements, hardened metal cutting elements, rotary cone type rockbits within the spirit and scope of the present invention.

It is also a feature of the present invention to provide a novel welldrilling system having a reamer bit that is rotationally driven by adrill string or by any other rotary drive mechanism and a core removalbit that is rotated along or near the longitudinal axis of the reamerbit.

It is another feature of the present invention to provide a novel welldrilling system having fluid flow control features to ensure optimumdrilling by a reamer bit and a core removal bit and to further ensureoptimum flow of drilling fluid for cooling of mud motor bearings and formud motor operation.

It is an even further feature of the present invention to provide anovel well drilling mechanism having a PDC reamer bit that is capable ofbeing rotationally driven by a rotary drill string or a mud motor thatis mounted to a non-rotary drill string and which defines a central bitopening within which is located a formation core removing rotary bitthat is independently driven in the direction of rotation of the reamerbit or in the opposite direction of rotation of the reamer bit by a coreremoval mud motor that is located within a drill housing and issupported by the body structure of the reamer bit.

Briefly, the various objects and features of the present invention arerealized through the provision of a steerable well drilling systemhaving a core removal bit assembly that is threaded directly into thebit box of a bent housing mud motor or other straight or directionalwell drilling system. As drilling fluid is pumped down-hole through thedrill string, the fluid will rotate the bit box on the bent housing mudmotor thereby rotating the housing structure that contains the coreremoval bit assembly. The mud motor bent housing is mounted to the lowerend of a drill string extending from the drilling rig at the surface andonly rotates if the drill string is rotated from above via rotary/kellyor by the top drive of a drilling rig. The steerable drilling assemblysimply extends the length from the drill bit to bend of the benthousing. The principal effect the drilling system will have is that thebuild rate, i.e., borehole deviation, will be less per 100 feet,resulting in borehole curvature of less radius in comparison. Thedrilling system is steered by selective rotary orientation and linearsliding in substantially the same manner as a conventional bent housingmotor is oriented for steering.

The dual bit drilling system of the present invention quite short,having a length of only about 4′ in a typical drilling application.Because of its short length, the drilling system can be used to drill astraight well or it can be threaded into the bit box of a bent housingmud motor and used to drill a directional well. A stabilizer istypically provided on a bent housing mud motor. This stabilizer willlikely need to be removed and a different stabilizer will need to beprovided along the length of the dual bit drilling system. Thestabilizer can be located on the dual bit drilling system at variousdistances from the drill bit depending on the drilling characteristicsthat are desired. The stabilizer can also be gauged or under gauged asdesired. The rotation speed of the inner core removal bit is determinedaccording to the characteristics of the different types of subsurfaceformations that are encountered. It is expected that the rate ofpenetration will increase geometrically since the inner core of theformation is continuously and completely cut away from the top down,rather than being chipped or crushed.

The short well drilling mechanism has a housing to which is mountedreamer bit having a small mud motor located within the housing andsupported by the body structure of the reamer bit. This small mud motoris arranged to drive a core removal bit at higher rpm's than that of thereamer bit. The rate of penetration of the well drilling system of thepresent invention, in comparison with conventional PDC drilling systems,increases geometrically. Because the present invention has a combinationof a PDC reamer bit with a mud motor driven core removal bit, which hasPDC cutters on the reamer bit, whether the core removal bit be centeredor offset from the center-line of the larger reamer bit, achievesefficient removal the formation core while drilling more efficientlywith the reamer bit.

The drilling mechanism of the present invention has basically comprisesan outer reamer that has been bored for a small mud motor bearing pack,with the core removal bit threaded to the small mud motor, and beingpositioned within the inner bit body. The mud motor bearing pack hasleft hand threads to resist the left hand reactive torque that itreceives and is threaded into the inner PDC bit body. Because the mudmotor is being supported by the reamer only and is subject to reactivetorque, all motor connections of the outer body have left hand threads.Left hand reactive torque of the mud motor will be applied to allconnections except the connection of the core removal bit to the bitdrive shaft. Only a small amount of power is required to rotate a 1¼″PDC core removal bit. The mud motor power section would be only about 2′in length. Also the mud motor has a smaller bearing pack with a largerpower section driving the PDC core removal bit to ensure adequaterotational power. The inner diameter of the short drive tube will allowa larger power section to be used. The PDC reamer has fluid passagesthat are nozzled to a specific size, creating internal bit pressure thatforces drilling fluid through the mud motor power section, rotating thecore removal bit below. Because the lower portion of the mud motorbearing pack is threaded into the inner part of the reamer, thislocation isolates the bearing pack fluid bypass opening from a highpressure chamber that is located in the upper part of the housing. Thisfeature allows the bearing pack fluid to divert to the lower pressure ofthe well bore annulus, thereby simultaneously cooling the mud motorbearing back and the core removal bit. A hardened internal reamer sleeveis positioned within a central bore of the reamer bit to prevent wear tothe reamer by the core removal bit. The entire drilling assembly isthreaded into the bit box of a bent housing mud motor for directionaldrilling, or is threaded into the bit box of a bottom hole assembly forstraight wellbore drilling.

Because the present invention has a combination of a PDC reamer with amud motor driven core removal bit, which has a PDC point or PDC cuttersmounted to it by means of cutter retention matrix or by any othersuitable means for cutter retention. Whether the core removal bit becentered or in laterally offset relation with the larger reamer, thecore removal bit cuts away the formation core more efficiently whiledrilling. The optimal offset distance of the core removal bit and thecenter of the reamer bit will be determined by the well drillingparameters at any point in time.

The dual drill bit system of the present invention would be about 4′long, comprising of an outer reamer that has been bored for a small mudmotor bearing pack, with the core removal bit screwed on, to slide intothe inner bit body. The mud motor bearing pack would have left handthreads since its reaction forces will be transmitted directly to thereamer bit body. The mud motor bearing pack is threaded directly intothe inner PDC bit body. Because the mud motor is being supported only bythe reamer, all motor connections will be in the form of left handthreads, except the core removal bit. Left hand reactive torque of themud motor will be applied to all connections except the core removalbit. It would not take very much power to turn a 1¼″ PDC core removalbit. The mud motor power section would be about 2′ in length. Also themud motor will have a smaller bearing pack with a larger power sectiondriving the PDC core removal bit. This will assure adequate rotationalpower for efficiently rotating the core removal bit. The inner diameterof the short drive tube is sufficiently large to allow a larger powersection to be used.

The PDC reamer would have fluid passages that could be nozzled to aspecific size, creating predetermined internal bit pressure, therebyforcing drilling fluid through the mud motor power section, rotating thecore removal bit below. Because the lower portion of the mud motorbearing pack is threaded into the inner part of the reamer bit, it wouldisolate the bearing pack fluid bypass opening from the high pressurechamber that is within the housing of the drilling system. This wouldallow the bearing pack fluid to be diverted to the lower pressure of thewell bore annulus, thereby simultaneously cooling the mud motor bearingback and the core removal bit. A hardened internal wear resisting sleeveis located within the reamer bit to prevent wear to the reamer bit bythe core removal bit. The complete drilling assembly is adapted to bethreaded into the bit box of a bent housing mud motor, for directionaldrilling or into a bottom hole assembly, for straight hole drilling.

The PDC cutters near the center of the reamers will slightly overlap thereamer core area, cutting the edge of the core and preventing corecontact with the reamer. Also because of well bore core removal, minimalbottom hole assembly weight is required to cause the PDC cutters toefficiently penetrate into the formation and drill a straight holeeffortlessly. As more weight added to any drill bit, it will force thedrill collars above to flex and lay to one side of the well bore,causing the drill bit to be cocked on an angle, thereby drilling off ina selected direction. If drilling continues in the selected direction,the angle of the drill bit will continually increase as additionalborehole is drilled. There will also be less heat generated by frictiondue to the cutting of formation, rather than having the PDC cuttersslide on top of the formation rather than cutting it, thereby extendingPDC drill bit life dramatically.

Significant vibration is typically experienced when the rotor of the mudmotor of the core removal bit is spinning within the stator. For thisreason, resilient stabilizers formed of rubber or rubber-like polymermaterial are added to the mud motor to absorb the vibration. Thisfeature prevents damage to the small PDC coated carbide bit spinning inthe core removal bit passage of the reamer bit. The offset core removalbit will be recessed behind the PDC cutters of the reamer bit and ispositioned for efficient removal of the formation core that remains asthe reamer bit penetrates into the formation. The optimal recesseddistance of the core removal bit is determined by the parameters of theformation being drilled; however, it should be borne in mind that theformation core can also serve to stabilize rotation of the reamer bit.With the core removal bit centered within the reamer bit, it can berecessed behind the PDC cutting members on the blades of the reamer bitand protrude out of the reamer bit, provided the core removal bit outerdiameter overlaps the PDC cutters in the center of the reamer bit.

Though the mud motor powered rotary drilling system or head mayincorporate a variety of formation cutting or eroding elements, such aspolycrystalline diamond (PDC) cutting elements and hardened metal rockcutting or chipping elements, for purposes of simplicity the inventionis discussed herein as it concerns formation boring by using PDC cuttingelements. The steerable drilling mechanism has a tubular housing that isconnected with a cross-over sub that is in turn connected with a drillstring extending from a drilling rig the surface. The lower end portionof the tubular housing is provided with a vibration isolation member todampen any vibration forces that are encountered. A reamer bit isconnected with the lower end of the tubular housing below a stabilizerthat ensures centering of the drilling system within the wellbore beingdrilled. A mud motor is located within the tubular housing of the welldrilling system and includes a rotor having an axis of rotation that canbe concentric or eccentric with respect to the longitudinal rotationalaxis of the tubular housing and reamer. The drilling fluid inlet of themud motor is in communication with a high pressure fluid chamber that isdefined within the tubular housing above a partition and with flowcontrol past the partition being controlled by an interchangeable flowcontrol nozzle.

A partition is preferably present within the tubular housing of thesteerable drilling system of the present invention and serves to isolatean internal fluid chamber from the high pressure within the fluidpassage of the drill string and bent housing mud motor. Aninterchangeable orifice flow control nozzle is present within thepartition for control of drilling fluid flow past the mud motor forcooling and cleaning of the reamer bit and for cooling and lubricatingthe bearing pack of the mud motor. The bottom hole steerable drillingmechanism incorporates an external reamer bit having a central portionwith no cutting elements, thus permitting a formation core to enter acentral opening of the reamer bit as formation drilling progresses. Theformation core that remains as the reamer bit is operated is cut away bya mud motor driven core removal bit that is located for mud motorpowered rotary movement within a central opening of the reamer bit.Preferably, the core removal bit is a carbide bit having core cuttingedges and being formed of carbide material that is preferably coatedwith PDC material. The core removal bit may have other forms; however itfunctions to cut away the remaining formation core from the top down aspenetration of the reamer bit progresses into the formation. The coreremoval bit mud motor is mounted within the reamer bit head typically bybeing threaded into a threaded receptacle of the reamer bit body. Thecore removal bit is provided with formation cutting elements and isrotated at a different, typically higher rate of rotation as comparedwith the rate of rotation of the reamer bit. However, if the coreremoval bit has the same rotary speed as the reamer bit, the rotaryspeed of the core removal bit will be added to the rotary speed of thereamer bit, causing the core removal bit to rotate at a faster rotaryspeed than the reamer bit. The reamer and core removal bits work inconcert to facilitate a greater overall formation penetration rate ascompared with conventional PDC drill bits. The fluid flow that operatesthe mud motor is also employed for cooling and cleaning of the coreremoval bit. The core removal bit has a plurality of drilling fluidpassages that permit the flow of drilling fluid for cleaning of thecutting elements of the core removal bit and for cooling and lubricatingthe bearing pack of the core removal bit to promote extended servicelife thereof. Drilling fluid flow through the reamer passages isselectively adjustable by means of replaceable flow control nozzles thatare sized according to well drilling parameters, such as well depth,formation character and hardness, fluid pressure at the drill bits, andthe like.

When the core removal or inner bit is rotated about an axis of rotationthat is offset from the rotational axis of the reamer bit, the coreremoving cutting edges of the core removal bit are not centered on thetop of the core, but rather cut across the top surface of the core tocut it away. Regardless how big or what the offset of the core removalbit is, the recessed core removal bit will always remove the remainingformation core that is not cut away by the PDC cutter elements of thereamer bit. As the formation core is continuously cut away by the coreremoval bit, it does not restrict the efficiency of formationpenetration by the PDC cutters of the reamer bit.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features, advantages andobjects of the present invention are attained and can be understood indetail, a more particular description of the invention, brieflysummarized above, may be had by reference to the preferred embodimentthereof which is illustrated in the appended drawings, which drawingsare incorporated as a part hereof.

It is to be noted however, that the appended drawings illustrate only atypical embodiment of this invention and are therefore not to beconsidered limiting of its scope, for the invention may admit to otherequally effective embodiments.

In the Drawings:

FIG. 1 is a schematic illustration showing a well drilling rig that islocated at the surface of the Earth's surface and extends a drill stringor stem into a wellbore that extends to one or more production zones andshows a well drilling mechanism embodying the principles of the presentinvention being connected with the drill string and being employed fordrilling a straight wellbore section:

FIG. 2 is a schematic illustration that is similar to the illustrationof FIG. 1 and shows the well drilling mechanism of FIG. 1 being employedto drill a deviated wellbore section that is directed toward a targetformation of interest;

FIG. 3 is a schematic illustration similar to that of FIGS. 1 and 2 andshowing the well drilling system of the present invention beingconnected with a bent housing directional drilling mechanism forcontrolled drilling of a deviated wellbore that transitions from avertical wellbore section;

FIG. 4 is a schematic illustration showing the well drilling system ofthe present invention being mounted to the bit box of a conventionalbent housing type directional drilling mechanism

FIG. 5 is a longitudinal sectional view showing a steerable dual bitwell drilling system embodying the principles of the present invention,being mounted to the bit box of a drill stem, mud motor or other rotarydrive mechanism and having an eccentrically located mud motor poweredcore removal bit for continuous formation core removal during drillingactivity;

FIG. 6 is a longitudinal sectional view showing the upper portion of thesteerable well drilling mechanism of FIG. 1 in greater detail andillustrating the eccentrically offset core removal bit and showing theupper portion of the small internal core removal bit mud motor indetail;

FIG. 7 is a longitudinal sectional view showing an enlarged view of thelower portion of the steerable drilling system of the present inventionessentially as shown in FIG. 1;

FIG. 8 is a bottom view showing the reamer bit of FIGS. 1-3 as havingadjustable fluid flow nozzles for drilling fluid control and showing alaterally offset core removal bit opening within which a core removalbit is located for central formation core removal;

FIG. 9 is a longitudinal sectional view showing a steerable dual bitwell drilling system embodying the principles of the present invention,being mounted to the bit box of a drill stem, mud motor or other rotarydrive mechanism and having an concentrically located mud motor poweredcore removal bit for continuous formation core removal during drillingactivity;

FIG. 10 is a longitudinal sectional view showing the upper portion ofthe steerable well drilling mechanism of FIG. 5 in greater detail andillustrating an upper portion of the core removal bit mud motor theconcentrically offset core removal bit and showing the upper portion ofthe small internal core removal bit mud motor in detail;

FIG. 11 is a longitudinal sectional view showing an enlarged view of thelower portion of the steerable drilling system of the present inventionessentially as shown in FIG. 5 and illustrating in detail the PDCcutting elements of the reamer bit and concentric core removal bit;

FIG. 12 is a bottom view showing the dual concentric bit drillingmechanism of FIGS. 5-7 and illustrating fluid flow control nozzles ofthe reamer and core removal bits;

FIG. 13 is a longitudinal sectional view showing a steerable dual bitwell drilling system embodying the principles of the present invention,being mounted to the bit box of a drill stem, mud motor or other rotarydrive mechanism and having an eccentrically located mud motor poweredcore removal bit having a splined connection of the core removal bitdrive mechanism with the rotor member of the core removal bit mud motor;

FIG. 14 is a longitudinal sectional view showing the upper portion ofthe steerable well drilling mechanism of FIG. 13 in greater detail andillustrating the splined connection of the core removal bit mud motor indetail;

FIG. 15 is a longitudinal sectional view showing an enlarged view of thelower portion of the steerable drilling system of the present inventionessentially as shown in FIG. 13;

FIG. 16 is a bottom view showing the dual bit drilling mechanism ofFIGS. 13-15 and illustrating fluid flow control nozzles of the reamerand core removal bits and the PDC core removing cutter members of theeccentric core removal bit;

FIG. 17 is a longitudinal sectional view showing a steerable dual bitwell drilling system embodying the principles of the present invention,being mounted to the bit box of a drill stem, mud motor or other rotarydrive mechanism and having a concentrically located mud motor poweredcore removal bit having a splined connection of the core removal bitdrive mechanism with the rotor member of the core removal bit mud motor;

FIG. 18 is a longitudinal sectional view showing the upper portion ofthe steerable well drilling mechanism of FIG. 17 in greater detail andillustrating the splined connection of the core removal bit mud motor indetail;

FIG. 19 is a longitudinal sectional view showing an enlarged view of thelower portion of the steerable drilling system of the present inventionessentially as shown in FIG. 17;

FIG. 20 is a bottom view showing the dual bit drilling mechanism ofFIGS. 17-19 and illustrating fluid flow control nozzles of the reamerand core removal bits and the PDC core removing cutter members of theeccentric core removal bit;

FIG. 21 is a longitudinal sectional view showing the lower section ofthe steerable dual bit well drilling system of the present inventionwith the mud motor and core removal bit of the dual bit well drillingmechanism being laterally offset and having gauge control elements beingmounted to ensure formation core controlled stability of the reamer bitagainst undesired lateral deviation from its intended course duringdrilling activity;

FIG. 22 is a longitudinal sectional view showing the lower section ofthe steerable dual bit well drilling system of FIG. 32 and showing aconcentrically arranged core removal bit positioned within a gauge linedcentral core receptacle of the reamer bit;

FIG. 23 is a longitudinal sectional view showing the core removal bit tobe eccentrically arranged within the reamer bit and having a gauge linedcore receptacle;

FIG. 24 is a longitudinal sectional view showing the lower section ofthe steerable dual bit well drilling system showing the core removal bitbeing concentrically arranged within a gauge lined core receptacle;

FIG. 25 is a bottom view showing the lower section of the steerable dualbit well drilling system showing the core removal bit to beeccentrically arranged with the reamer bit and having a gauged corereceptacle within the reamer bit for steering control and stability andshowing reamer vane or blade overlap of a part of the core removal bit;

FIG. 26 is a longitudinal sectional view showing the lower section ofthe steerable dual bit well drilling system showing a reamer bitgeometry having a depending central projection having internal andexternal gauge members for stability and steering control;

FIG. 27 is a bottom view of the well drilling mechanism of FIG. 26;

FIG. 28 is a longitudinal sectional view showing the lower section ofthe steerable dual bit well drilling system showing the core removal bitbeing concentrically arranged within a PDC gauge lined core receptacleand being of a larger diameter as compared with the diameter of thegauge lined core receptacle of the reamer bit;

FIG. 29 is a bottom view of the dual bit well drilling mechanism of FIG.28;

FIG. 30 is a bottom view of an embodiment of the present inventionhaving a right hand rotatable reamer bit with PDC cutter supportingblades extending near the axis of bit rotation and showing a left handrotatable core removal bit being eccentrically located relative to thereamer axis and being of sufficient diameter to overlie a formation corethat remains from reamer bit drilling;

FIG. 31 is a bottom view of the dual bit drilling system of the presentinvention that differs from FIG. 30 only in that the reamer bit and coreremoval bit have three equally spaced cutter supporting blade members:and

FIG. 32 is a longitudinal section view showing the well drillingmechanism of FIG. 30 and showing further details of the reamer bit andcore removal bit and the mud motor drive mechanism for the core removalbit.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENT

While the well drilling system is discussed herein particularly as itconcerns PDC drill bits, it is not intended to limit the spirit andscope of the present invention to such, since this invention isadaptable to a variety of drilling systems, including systems foreffectively drilling other materials. Referring now to the drawings andfirst to the schematic illustration of FIG. 1, a well drilling rig 10 isshown that is located at the surface “S” of the Earth. The well drillingrig has a rotary turntable 12, rotary top drive or other rotary drivemechanism for rotating a kelly 14 to which is connected a drill string16 that is composed of multiple sections of drill pipe, also known asdrill stem. The drill string 16 extends from the drilling rig into awellbore 18 that is being drilled through various earth formations 20 toone or more production zones that may contain crude oil, natural gas,distillate and other petroleum products. The drill stem or pipe 16 ofthe drill string is tubular and defines a central flow passage 22through which drilling fluid, also called drilling mud, is pumped forthe purpose of cooling the drilling mechanism and flushing away drillcuttings and other debris that is loosened from the formation duringdrilling. When drilling a straight wellbore, the rotary drive mechanismof a drilling rig continually rotates the drill string and drillingfluid is continuously pumped through the drill pipe and weight isapplied through the drilling string to the drill bit to drill straightahead. When the well drilling system is being used to drill adirectional wellbore, as drilling fluid is through the drill pipe andwith the drill string stationary, a bent housing mud motor isrotationally oriented to the desired direction for wellbore deviation.The well driller will then slide the drill string ahead to correct thecourse of the wellbore or to change the wellbore direction. Aftersliding the drill string a desired distance to achieve the wellcorrection or change that is desired, the driller will then begin torotate the drill string and once again drill straight ahead.

A drilling mechanism 26 is connected with the bit box of the mud motorpowered drilling mechanism 24, will be hydraulically powered by thepressurized drilling fluid being pumped through the drill stem to thedrill bit or bits 28 of the well drilling mechanism 26. Every mud motorhas two sets of threads, internal threads and external threads. With astandard mud motor, the internal and external threads constitute righthand threads because the mud motor is supported at its upper end by thedrill string. The left hand reactive torque that occurs during drillingtends to tighten all of the right hand threads of the outer body of themud motor. All internal threads of the rotor constitute right handthreads because the motor rotor drives the drill bit to the right andthus has the effect of tightening all of the threads beneath it.

The opposite effect occurs during the practice of the present invention.The mud motor for driving the core removal bit of the present inventionis not supported at its upper end by the drill string as is typicallythe case, but rather has its lower end mounted to and supported by thereamer bit body. In essence, the mud motor for driving the core removalbit is supported only at its bottom end by its connection with thereamer bit. When supporting the tubular housing of the mud motor at thebottom, if the core removal bit is being rotated to the right by the mudmotor, the core removal bit and all internal threads of the bit drivemechanism must have right hand threads but all external tubular mudmotor body threads must be left hand threads because the reactive torqueis to the left. If the core removal bit is rotated to the left by itsmud motor, the core removal bit and all internal threads must be lefthand threads, but all external motor body threads must be right handthreads because the reactive torque of the core removal bit against theformation core being cut away from the top down is to the right.

According to the spirit and scope of the present invention, as shown inFIG. 5, at the lower or distal end of the drill string 16 is mounted adual bit steerable drilling mechanism 30, which may be rotated by thedrill string, when the drill string is rotated by the drilling rig, ormay be powered by a drilling fluid energized mud motor that is connectedto the drill string. The dual bit steerable well drilling mechanism 30is employed to achieve rotation of a reamer bit, shown generally at 32,and a core removal bit, shown generally at 34, both being shown at thelower portion of FIG. 5 and being shown in later Figures of thedrawings. The dual bit steerable well drilling mechanism 30 comprises atubular housing, shown generally at 36, which is comprised of a mountingsub 38 which defines an upwardly projecting externally threadedconnection 40 that is received by the internally threaded receptacle 42of a bit box 44. The bit box 44 may be defined by a drilling sub at thelower end of the drill string or by the rotary output shaft of a mudmotor that is intended for either straight or directional drilling. Thetubular housing 36 further includes an intermediate housing section 46having an upper threaded connection 48 in assembly with the mounting sub38 and a lower threaded connection 50 with a reamer bit body 52. Theintermediate housing section 46 is typically provided with a pluralityof external elongate radially spaced centralizer members 54 thatcentralize the drilling mechanism within the wellbore and with thespaces between the centralizer members defining flow passages within thewellbore and externally of the tubular housing for the return flow ofdrilling fluid and drill cuttings after the drilling fluid has beendischarged from the drill bit mechanism of the well drilling system.

The reamer bit body 52 is typically composed of a durable metalcomposition, such as steel, and defines an external surface 54 to whicha cutter retention matrix 56 is affixed by bonding, welding or by anyother suitable means for attachment. As is evident in FIG. 7 and fromthe bottom view of FIG. 8, the cutter retention matrix 56 is formed todefine a plurality of outwardly radiating curved vanes 58, havingleading edge portions 60 that define a multiplicity of cutterreceptacles 62 each having a PDC cutter element 64 secured immovablytherein. Thus, a plurality of curved arrays of PDC cutter elements 64are each arranged to present cutting edges that engage and cut away asmall portion of the formation interface during each rotationalrevolution of the reamer bit. Collectively, the curved arrays of PDCcutter elements 64 continuously cut away the major portion of theformation material within which the wellbore is being drilled. Gauge orwear pad members 66, which may be defined by PDC members or by any otherhard and wear resistant material, are retained by the cutter retentionmatrix material 56 and serve to minimize the potential for wear of thecutter retention matrix material as the outer wall of the reamer bit isrotated in contact with the abrasive wall surface of the wellbore.

When drilling with conventional PDC bits the PDC cutter elements tend tocrush the central portion of the formation material within the borehole,rather than cut it away, due to the inefficient cutting characteristicsof the PDC cutters at the central region of the bit. Even when a PDC bitis provided with a small concentric bit, such as taught by U.S. Pat. No.8,201,642, for drilling a central portion of a borehole, the smallconcentric bit would tend to crush, rather than cut away the formationmaterial due to the inefficient formation cutting characteristics of thecentrally located formation cutting elements of the small concentricbit. However, as is evident from FIGS. 5 and 7 of the drawings, thereamer body 52 defines a downwardly facing central opening 68 which,since the reamer bit has no central cutter elements, maximizes formationcutting efficiency. The open central portion of the reamer bit presentsvirtually no resistance to bit penetration as is typically experiencedby conventional PDC drill bits having formation cutter elements at thecentral portions thereof. However, during drilling activity a centralcore portion of formation material is not cut away, since no cuttingelements are present, and enters the central opening 68. A core removalbit 34 is provided to efficiently cut away this central formation core.In the case of the dual bit steerable well drilling mechanism shown inFIGS. 5-8, the tubular housing 36 defines a longitudinal center-lineC/L¹ which is concentric with the center of the flow passage 22,concentric with the connecting sub 38 of the housing and concentric withthe centers of the intermediate housing section 46 as well as the reamerbit body 52. However, the cylindrical wall surface 76 of the centralopening 68 of the reamer bit body 52 is eccentric with respect to thereamer bit body, such that its center-line C/L² is laterally offset withrespect to center-line C/L¹ of the reamer bit body 52. It should beborne in mind, however, that the core removal bit can be eithereccentrically located or concentrically located with respect to thecenter-line C/L¹.

As shown in FIGS. 1 and 7, the core removal bit 34 is positioned withinthe central opening 68 for rotation about the center-line C/L² and has acore cutting face 70 that is recessed within the central opening 68. Thecore cutting face is provided with a plurality of PDC cutting elements72 that serve to continuously and completely cut away the remainingformation core that is not cut away by the cutting elements of thereamer bit 32. It should be noted that the reamer bit 32 may be rotatedby a rotating drill string or by a drilling fluid energized mud motor.However, the core removal bit is independently rotated by a drillingfluid powered core removal bit mud motor shown generally at 74 which islocated within the tubular housing 36 of the well drilling mechanism 30.

For core removal bit mud motor support, as shown in FIG. 7, the reamerbit body member 52 defines a substantially vertical bore 76 having thelaterally offset center-line C/L² as its center. The vertical bore 76defines an internally threaded upper extent 78 within which the upperexternally threaded end portion of a bearing support sleeve member 80 isseated. The bearing support sleeve member 80 also serves as an internalwear resisting liner to protect the core removal bit 34 againstexcessive wear during drilling operations. A plurality of annular sealmembers 81 are carried within seal grooves of the bearing support sleevemember 80 and establish high pressure sealing with the internalcylindrical surface 75 of the vertical bore 76. An outer bearing member82 is located within the bearing support sleeve member 80 and an innerbearing member 84 is mounted to a core removal bit drive shaft 86 whichis driven by the core removal bit mud motor 74. The bearing supportsleeve member 80 carries a plurality of spaced seal members 81, such asO-rings, that establish a sealed barrier between the bearing supportmember and the internal cylindrical surface 83 of the substantiallyvertical bore 76 of the reamer bit body 52. The bearing support member80 defines a mud motor tube mount 88 at its upper end portion which hasa downwardly facing shoulder 90 that is seated on an internal upwardlyfacing surface 92 of the reamer bit body 52. An upstanding externallythreaded section 94 of the mud motor tube mount 88 is engaged by aninternally threaded section 96 of a tubular mud motor housing 98 of thecore removal bit mud motor 74 to provide for stabilizing support of thecore removal bit mud motor. The core removal bit mud motor has a bearingpack shown generally at 100 which includes spaced sets of radialbearings 102 and 104 and thrust bearings 106. An annular fluid flowclearance or passage 103 exists through the bearing pack 100, therebypermitting drilling fluid flow through the bearing pack for cleaning andcooling the bearings and materially enhancing the service life of thecore removal bit mud motor and its bearing members. The drilling fluidis discharged from the clearance or flow passage of the bearing pack andthen flows through the clearance between the core removal bit 34 and theformation core receptacle within which the core removal bit is alsopositioned for core cutting rotation.

As shown in FIG. 1 and in greater detail in FIG. 6, the tubular housing98 of the core removal bit mud motor 74 contains a fixed stator member108 that is composed of a resilient material such as rubber or any of anumber of suitable resilient polymer materials. The stator memberdefines a generally helical internal profile. A rotor member 110 isrotatable within the stator member and has a corresponding generallyhelical external profile. Pressurized drilling fluid being suppliedthrough the flow passages of the drill string, flow passage 22 of thebit box 24 and the internal fluid passage 112 of the mounting sub 38enters a high pressure chamber 114 of the steerable well drillingmechanism 30. A portion of the pressurized drilling fluid of the chamber114 enters a mud motor actuation passage 116 via an opening that isdefined by an inlet fitting 118 that forms the upper extent of the coreremoval bit mud motor 74. A flow control nozzle 119 may be threaded Thepressurized drilling fluid within the mud motor actuation passage 116acts on the geometries of the internal and external helical profiles ofthe stator and rotor of the core removal bit mud motor and causeshydraulically energized rotation of the rotor member and applies a motortorque to a non-circular shaft drive member 120. A mud motor outputshaft 122 receives and is driven by the lower non-circular shaft drivemember 120.

During operation of the core removal bit mud motor 74 pressurizeddrilling fluid is discharged from the rotor and stator interface andenters an annular flow passage 124 that is located about the mud motoroutput shaft 122 and the inner surface of the tubular housing 98. Thisflow of drilling fluid serves for cooling and lubrication of the bearingpack 100. The lower end portion of the mud motor output shaft 122defines a tubular cross-over member 126 that has transverse fluid inletopenings 128 through which pressurized drilling fluid transitions fromthe annular flow passage 124 to a flow passage 130 within the coreremoval bit drive shaft 86. The body member 132 of the core removal bit34 is threaded to the lower end of the core removal bit drive shaft anddefines diverging drilling fluid passages 134 that conduct flowingdrilling fluid to a plurality of fluid flow control nozzles 136. Thefluid flow control nozzles 136 are sized to provide an optimum rate ofdrilling fluid flow to the cutting interface of the core removal bit 34for efficient cooling and cleaning of the core removal bit as thedrilling operation is being conducted.

For cooling and cleaning of the reamer bit 32 the reamer bit body 52 hasa plurality of fluid supply passages, two of which are shown at 138 and140 in FIG. 7. At the outlet portions of these fluid supply passagesfluid flow control nozzles are mounted as shown at 142 and 144. Thesefluid flow control nozzles are sized according to wellbore parameters,such as formation depth, temperature, pressure, etc. and can be changedor selected to ensure optimum flow of drilling fluid for efficientformation cutting, drill bit cooling and for flushing away drillcuttings. As is evident from the bottom view of FIG. 8 an annularclearance 146 exists between the outer periphery of the core removal bit34 and the inner surface of the central opening 68. A small volume ofpressurized drilling fluid flows within this annular clearance 146 forcleaning and cooling the core removal bit and motor bearings as the coreremoval bit is independently rotated and oscillated in response torotation of the reamer bit.

During borehole drilling with the reamer bit 32, the core removal bit 34of FIGS. 5-7, being eccentrically located with respect to the center ofthe reamer bit, will have an orbital motion as well as being rotatedindependently of the rotary motion of the reamer bit. This orbitalmotion causes the PDC cutter members of the core removal bit to sweepacross the central region of the borehole, thereby continuously cuttingaway the small core that remains as the formation is cut away by thereamer bit. The core removal bit is rotated by the core removal bit mudmotor, which requires very little power for its operation, because ofits small size in comparison with the size of the reamer bit. The coreremoval bit is driven at a significantly greater rotary speed whichcauses its PDC cutter members to move at an optimum speed relative tothe formation for efficiently cutting away the core region of theformation, without developing elevated heat. Moreover, the core removalbit is efficiently cooled during its operation by the volume of drillingfluid that is discharged at its cutting face from the fluid controlnozzles of the core removal bit and from the clearance between the coreremoval bit and the central opening of the reamer bit.

Referring now to FIGS. 9-12 a dual bit steerable well drilling mechanismis shown generally at 150 which differs from the dual bit steerable welldrilling mechanism 30 of FIGS. 5-8 principally in the concentricarrangement of the core removal bit 34 with respect to the reamer bit32. In this case, the central opening 68 of the reamer bit is concentricwith respect to the center-line of the reamer bit and with virtually allof the tubular components of the tubular housing and core removal bitmud motor. Though the core removal bit is rotated by its mud motor 74 inthe same manner as discussed above, it will not have oscillating motionduring rotation of the core removal bit. To continuously cut away thecentral core that remains due to rotary cutting of the borehole by thereamer bit, the core removal bit will simply be rotated by the coreremoval bit mud motor and will rely totally on the arrangement andcutting capability of the arrays of PDC cutting elements that areaffixed thereto.

As shown in FIGS. 13-16 the dual bit steerable well drilling mechanismshown generally at 160 has a bearing pack 162 having a tubular bearingpack support 164 that is mounted to the reamer bit body 52 insubstantially the same manner by a tube mount 88 as discussed above inconnection with FIG. 7. A rotary hydraulically energized drilling motor,also known as a mud motor, is shown generally at 166 and includes astator member 168 having a stator body composed of resilient materialsuch as rubber or a suitable polymer material and defining a helicalinternal profile 170. A rotor member 172 is supported within the statormember 168 and has a rotor body 174 that is also composed of a resilientmaterial. The rotor body 174 defines a generally helical externalprofile 176 that serves cooperatively with the internal stator profile170 to develop rotary torque force that causes rotation of the rotormember at a speed and torque force that is determined by the volume,size, length and stator/rotary lobe configuration of the motor anddrilling fluid flow from the drill string. The rotor member 172 is oftubular form and defines an internal surface 173 that defines aninternal rotor chamber or passage 175. The rotor member defines a bottomopening 177 permitting movement of a flexible rotor driven mud motoroutput shaft 178. Since it is known that the rotor member of a mud motorhas uneven rotation speed during its operation and tends to have ajerking rotary characteristic that is communicated to a drill bit or anyother device to which it is connected, it is desirable to minimize thisjerking rotary characteristic. The rotor driven shaft 178 is formed of aflexible material such as beryllium copper and has a thin flexible shaftportion that yields and is flexed by the forces the shaft receives fromrotor movement of the mud motor. Shaft flexing or yielding in thismanner cushions the jerking rotary characteristic of the rotor and thuscushions the formation cutting forces that are communicated to the drillbit. The rotor driven shaft 178 has an enlargement 182 at its upper endportion that is maintained in non-rotatable relation with the rotormember 172 by an engaging spline and groove connection 180. The shaftenlargement 182 of the rotor driven shaft 178 has an upwardly facingshoulder 184 that is secured against a transverse rotor wall 186 bylock-nut members 188 and 190 that are threaded to an externally threadedupper portion 192 of the rotor driven shaft. Thus, upon drilling fluidenergized rotation of the rotor member 172 the rotor driven shaft 178 isalso rotated. As shown in FIG. 15 a core removal bit operating shaft 200is located within the tubular bearing support member 164 and is mountedfor rotation within the bearings of the bearing pack. At the lower endportion of the rotor driven shaft 178 is defined a connector member 204that establishes non-rotatable connection with the upper end portion 202of a core removal bit operating shaft 200.

It is necessary that the motor bearing discharge be at a lower pressurethan at the inlet of the motor. This differential pressure conditionwill cause the drilling fluid or drilling mud to be forced through thebearing pack, achieving cooling and lubrication of the bearing pack.This design causes the mud motor bearing fluid to be discharged into thelower pressure condition of the well bore atmosphere. A major portion ofthe drilling fluid that enters the internal chamber 114 of the housing36, which is referred to as a high pressure chamber, and progressesthrough the interface of the stator member 168 and the rotor member 172is discharged into an annular drilling fluid supply chamber 194, whichis also a high pressure chamber or cavity due to high pressure fluidprogression through the contoured interface of the rotor and statormembers. The drilling fluid then enters the fluid supply passages 138and 140 and then flows through the fluid control nozzles 142 and 144 asshown in FIG. 16. After the drilling fluid exits the rotor/statorinterface of the mud motor into chamber 194, then a portion of the fluidenters the lower opening in rotor chamber 175 as shown in FIG. 15. Thefluid then flows up inside chamber 175 to the opening at the top of themotor bearing pack, then passes down through the fluid passages of thebearing pack and exits into the lower pressure of the wellboreatmosphere. The drilling fluid discharged into the spaces 214 betweenthe curved vanes or blade members 206 of the reamer bit 34 at thecutting interface of the core removal bit with the formation core thatremains as the reamer bit penetrates the formation. The PDC cutterelements 208 achieve cutting of the formation in the presence ofsufficient drilling fluid for cooling and lubrication of the cutterelements and for flushing away drill cuttings that are transported tothe surface via the annulus between the drill string and the surface ofthe wellbore that has been drilled.

As shown in FIGS. 14 and 15, the flexible mud motor operating shaft 178defines a drilling fluid flow passage 196 throughout its length. A fluidflow control nozzle 198 is threaded to or otherwise mounted to the upperend of the mud motor operating shaft 178 and serves to control the flowof drilling fluid from the internal housing chamber 114 into thedrilling fluid flow passage 196. A core removal bit operating shaft 200is positioned for rotation within the tubular bearing support member 164and has its upper end portion 202 mounted to a connector member 204 thatis defined by the lower extremity of the mud motor operating shaft 178.The core removal bit operating shaft 200 is supported for rotationwithin the tubular bearing support member 164 by the various bearingmembers of the bearing pack 162. As is evident in FIGS. 15 and 16 thecore removal bit 34 is threaded to the lower end of the core removal bitoperating shaft 200 and is provided with a plurality of curved blade orvane members 206, each having a plurality of PDC core cutting members208 mounted to the leading edge thereof.

As shown in FIG. 15, the core removal bit operating shaft 200 defines acentral fluid flow passage 210 which is in communication with the fluidflow passage 196 of the mud motor operating shaft 178 and serves toconduct drilling fluid to the core removal bit 34 for cooling andcleaning during drilling. The core removal bit defines a plurality ofdiverging fluid flow passages 212 that communicate with the centralfluid flow passage 210 and have fluid discharge openings in the spaces214 between the blades 206 or vanes of the core removal bit. Fluiddischarge control nozzles 216 are threaded into the fluid dischargeopenings and serve to control the discharge of drilling fluid to thecutting face of the core removal bit 34. Like the fluid flow controlnozzles 142 and 144 of the reamer bit 32, the fluid flow control nozzles216 of the core removal bit may be replaced by fluid flow controlnozzles having flow controlling characteristics that are suitable fordifferent well characteristics such as depth, formation pressure,temperature, etc. Thus, the drill bit can easily be tailored to theneeds of the drilling operation at any point in time.

FIGS. 19 and 20 illustrate a dual bit steerable well drilling mechanismgenerally at 220 that differs from the drilling system of FIGS. 13-16only in that the core removal bit 34 is concentrically arranged withinthe reamer bit 32 rather than being eccentric as is evident in FIGS.13-16. It should be noted, regardless whether the core removal bit iseccentrically or concentrically located with respect to the center-lineof the reamer bit, that drilling activity develops left hand reactivetorque on all of the threaded connections of the mud motor, withexception of the threaded connection of the core removal bit to the coreremoval bit operating shaft 200. For this reason, the threadedconnections of the rotary components of the mud motor will have lefthand threads to prevent unthreading of these connections by the lefthand reactive torque.

With reference to FIGS. 21 and 22 the dual bit steerable drilling systemthat is shown in the longitudinal sectional view of the bottom sectionof the well drilling mechanism employs a core removal bit 34 that iseccentrically located with respect to the center-line C/L¹ of thetubular housing 36. The core removal bit defines a plurality ofdiverging fluid flow passages 222 that are in communication with thecentral fluid flow passage 210 of core removal bit operating shaft 200and have fluid discharge openings 224 that direct discharge streams ofdrilling fluid downwardly against the formation core that remains as thePDC cutting elements 64 of the reamer bit cut away the formationmaterial during wellbore drilling. The diverging fluid distributionpassages of the core removal bit have flow control nozzles 226 thatcontrol injection of drilling fluid from the core removal bit into thewellbore according to various well conditions. These flow controlnozzles can be replaced with flow control nozzles of different flowcontrolling capacity as the well conditions change. Like the reamer bit32, the core removal bit 34 may have any number of radiating curvedvanes or blades, for example 3, 6 or 8 blades on which are mounted PDCformation cutter elements. For example in FIG. 25 the core removal bit34 is shown to have 4 curved cutter supporting blades.

Also, if desired, the inner cylindrical wall surface that defined thedownwardly facing central opening 68 may be provided with internaland/or external wear resisting pad members which serve as formation coregauge protection to prevent wear on the internal reamer blades core areaof the matrix body, thereby producing a constant core size for PDCreamer bit stabilization during drilling activity. This feature permitsthe formation core to stabilize drilling rotation of the dual bitmechanism and prevent its otherwise uncontrolled lateral excursionwithin the formation, which as mentioned above, causes undesiredenlargement and/or misdirection of the wellbore being drilled. Thisfeature ensures that the resulting wellbore will have the designed gaugethroughout. Gauge protection is also important from the standpoint ofcutter element protection. In a dual bit arrangement having a coreremoval bit, without gauge protection the formation core can become wornto the point that lateral off-direction or gauge enlarging movement ofthe drill bit will occur in the formation. When the gauge of thewellbore becomes enlarged the drill bit can oscillate back and forthwithin the wellbore. This back and forth movement can cause the PDCcutter elements of the core removal bit to become sheared away, thusessentially destroying its drilling capability. The presence of theformation core within the downwardly facing central opening 68, assumingthe core is not excessively worn, provides for rotational stability ofthe drill bit and resists lateral movement of the drill bit within theformation.

If a drill bit manufacturer were to make the PDC blades of the reamerbit slightly longer, the result would be a longer core receivingreceptacle as shown in FIG. 21, thus causing the formation core to be ofgreater length. The longer core functions to stabilize the rotation ofthe bit and to minimize its lateral movement within the formation. Alonger and larger diameter formation core will provide better and moreefficient stabilization of a drill bit during drilling by restraininglateral movement of the drill bit within the formation, thus ensuringthat the resulting wellbore is of the proper gauge. To provide thedesired gauge protection, wear resisting members 228 are provided on theinner parts of the PDC cutter supporting blades and serve to minimizeabrasive contact of the blades with the formation core. The wearresisting members serve as gauge protectors and prevent the blades fromwearing and reducing the diameter of the formation core and also preventthe erosive effect of the formation core from wearing the cutterretention matrix material of the inner parts of the blades. If this isnot done, the stabilization effect of the core on the bit willeventually be lost through wear or erosion of the formation core or thematrix material of the drill bit and the drill bit will then tend tomove laterally within the formation. The inner stabilization that isprovided by the formation core can influence the bit design. Rather thanemploying the current rounded contour of the outer diameter of a PDCdrill bit, so that the drill bit essentially wedges into the boreholefor straight drill tracking, the formation core resists lateral movementof the drill bit and causes the drill bit to progress along a straightcourse during drilling. This feature permits the bit design to bechanged to a more straight or flat bottomed design with minimal roundeddesign portions, thus significantly minimizing the number of PDC cutterelements that are needed for efficient drilling and minimizing the costof the drill bit.

With increased space in the center of the reamer bit, essentially areamer bit that has no center, a bit designer can have 4 or more PDCcutter supporting blades extending to the core. Thus 4 or more gaugeprotected blades are present for stabilizing engagement with theformation core. The downwardly facing central opening can besufficiently large to allow a 2 inch or larger core to enter the corereceiving receptacle of the reamer bit. The size of the formation corethat enters the downwardly facing opening of the reamer bit isdetermined by the size of the reamer bit. Thus, the core can be largeror smaller than 3″. A concentric or eccentric core removal bit having adiameter of about 3 inches can be positioned for cutting engagement withthe 2 inch or larger core. If the core removal bit is eccentricallylocated, the bit will be offset behind central portions the blades ofthe reamer bit but outside the body of the bit. This feature allows forthe drill cuttings of the core removal bit to be transported into theborehole being drilled by the flushing activity of the drilling fluidbeing discharged from the core removal bit.

FIG. 21 shows the lower portion of a dual bit steerable well drillingsystem that differs from the drilling system of FIG. 19 in the presenceof one or more internal formation cutter supporting vanes or blades 230that overlap a portion of the central opening 68 and are provided withwear resisting gauge protector members 228. During rotation of thereamer bit 32 about the center-line C/L¹ the centermost cutter elements232 provide for cutting away the formation material and leaving acentral core of formation material within the vertical bore that definesthe central opening 68. To ensure that central core is not diminished inwidth by wear due to its engagement by the internal surface that definesthe central opening 68, the gauge protectors 228, being composed of awear resisting material, such as PDC will protect the central coreagainst unusual wear. The gauge protectors will also minimize abrasivewear of the PDC retaining matrix material and significantly extend theservice life of the reamer bit.

The PDC cutters near the center of the reamer bit slightly overlaps theformation core receptacle of the reamer bit and will have cuttingengagement with the outer peripheral surface of the core, therebypreventing the formation core from being in contact with any portion thereamer bit. Also because of well bore core removal, little bottom holeassembly weight is required for PDC cutter elements to penetrate intothe formation, thereby permitting a straight wellbore to be effortlesslydrilled. As additional weight added to any drill bit, this added weightwill force the drill collars above the dual bit drilling system to flexand essentially become positioned one side of the well bore, causing thedrill bit to be cocked on an angle and thereby drilling off in thedirection of the angle. As drilling continues, this angle willcontinually increase as the wellbore is drilled into the formation. Lessheat is generated by friction due to efficient cutting of the formationby the PDC cutting elements, rather than having the inefficient centralcutters of a PDC bit typically sliding on top of the formation, therebyextending PDC drill bit service life dramatically.

FIG. 22 shows the lower section of the dual drill bit mechanism, havingreamer bit blade members 234 of greater axial length as compared withthe axial length shown in FIG. 15. By employing blade members of longerlength, the core removal bit 34 is retracted to a greater extent withinthe reamer body bore 76. The radially inner surface portions of thereamer bit blade members 234 are also provided with internal gaugeprotector members 228 to minimize wear or erosion of the cuter retainingmatrix material of the blade members. The gauge protectors also minimizewear of the formation core and thus maintain the stability and straightdrilling capability of the PDC well drilling mechanism.

The longitudinal sectional view of FIG. 23 illustrates a reamer havingan eccentrically located core removal bit, wherein the reamer bit isprovided with a plurality of blade members 236 that are of greater axiallength at the central portions thereof than at the outer portionsthereof, and thus defines a downwardly and inwardly tapered generallyconical blade geometry. This tapered blade geometry promotes wedging ofthe reamer bit into the bottom of the wellbore being drilled andpromotes straight drill bit tracking in the formation, unless wellboreangle is intentionally caused by controlled application of weight. Thislonger cutter supporting blade design also promotes the presence of afairly long bottom inlet opening 238 and permits the remaining formationcore to be of significant axial length for efficient lateral support ofthe reamer bit against lateral movement in the formation while drilling.Additionally, the interior surfaces of the cutter supporting blademembers are provided with gauge protectors to minimize wear to theformation core and the cutter retention matrix of the blades. Portions240 of the cutter supporting blade members 236 overlap portions of thecore removal bit 34 in the manner and for the purpose that is describedabove in connection with FIG. 21. Additionally, the divergingorientation of the PDC cutter elements 239 near the central opening 68provide the remaining formation core with a fairly large tapered baseportion, adding to the structural integrity and stability of theformation core. Since the reamer bit is rotated about its center-lineC/L¹ during drilling, the central formation core that is left by theformation cutting activity of the reamer bit will be of considerablelength and width and therefore will provide the reamer bit withexcellent gauge protecting stability against lateral movement of thereamer bit within the formation being drilled.

According to the longitudinal sectional view of FIG. 24, the PDC cuttersupport blade members 242 are rotated about the concentric center-lineC/L, thus ensuring that the central formation core that remains due toreamer bit drilling will be of greater width or diameter as comparedwith the eccentric core removal bit configuration of FIG. 23. The lengthof the formation core will be approximately the same as shown in FIG.21. The generally vertical bore 67 defining the downwardly facingcentral opening 68 is at least partially lined by a plurality of gaugeprotector members 228 that minimize erosion of the central formationcore to ensure against lateral movement of the reamer bit duringdrilling and also minimize wear of the cutter retention matrix materialat the inner portions of the PDC cutter retaining blades 242. FIG. 25 isa bottom view showing the eccentric relationship of the downwardlyfacing opening with respect to the bore 76 for the core removal bit andcore removal bit mud motor drive mechanism and further showing overlapof inner portions 230 of the curved PDC cutter retention vanes or blades236 of the reamer bit.

With reference to FIGS. 26 and 27, the longitudinal sectional view ofFIG. 26 shows a dual bit, steerable well drilling mechanism that issimilar to the drilling mechanism of FIG. 23, with the exception of theconfiguration of the cutter retention matrix of the reamer bit 32. Theblade forming and cutter retention matrix 56 of the reamer bit 32defines a central extension 244 of circular configuration, which isconcentric with the reamer bit and defines an outer circular surface 246as is evident in FIG. 27. Wear resistant gauge protector members 248 aremounted to the matrix material and have wear surfaces that areessentially co-extensive with the cylindrical outer surface 246 of thecentral extension 244. As the reamer bit is rotated within the formationduring drilling activity, the gauge protection members 248 minimizeerosive wear of the formation wall immediately adjacent the cylindricalsurface 246 and also minimize wear of the outer cylindrical surface 246of the matrix material. This feature minimizes the potential for thereamer bit moving laterally within the formation and causing thewellbore to become off gauge. As is evident in the bottom view of FIG.27, the downwardly facing outer peripheral portions of the reamer bitdefine a plurality of curved vanes or blades 250 that have spaces andprovide for orientation and support of a multiplicity of PDC cutterelements 252. Likewise, the downwardly facing tapered surface portion254 of the central extension 244 also defines a plurality of spacedcurved vanes or blades 256 that also provide for orientation and supportof a multiplicity of PDC cutter elements 258.

As shown in FIG. 26, the bore 76 that defines the downwardly facingcentral opening 68 of the reamer bit 32 is eccentrically located withrespect to the center-line C/L¹ of the tubular housing 36 and the reamerbit body 52 so that its center-line C/L² is laterally offset. Thisfeature causes the radially inner portions of the curved vanes or bladesof the PDC cutter support matrix material to overlap the bore 76 asshown at 260 in FIGS. 26 and 27. The core removal bit member 34 isrecessed within the bore 76 to provide space 262 for fluid entrainmentand flushing of drill cuttings away from the cutting face of the coreremoval bit 34 by means of the drilling fluid that is discharged fromthe fluid distribution passages of the core removal bit.

Internal gauge protector elements 264 are mounted to the matrix material56 within the downwardly facing central opening 68, as shown in FIGS. 26and 27 and serve to minimize erosive wear of the formation core that ispresent within the downwardly facing central opening 68 during drilling.The gauge protector elements 264 also minimize erosive wear of the innerperipheral surface that defines the downwardly facing central opening.Thus, the formation core provides for stability of the reamer bit duringdrilling and ensures against the lateral deflection or drifting that istypically inherent in conventional PDC drill bits.

FIGS. 28 and 29 illustrate the dual bit steerable well drilling systemof the present invention and show the core removal bit 34 as beingconcentric with the reamer bit. As shown in FIG. 28 the generallyvertical bore 76 that defines the downwardly facing central opening 68and the bore 77 within which the core removal bit 34 is maintained forrotation by the internal mud motor 74, both being rotated in concentricrelation with the center-line C/L. The core removal bit 34 has itscutting face retracted within the downwardly facing central opening 68and is located within an enlarged section 266 of the bore 76. The PDCcutter elements that are present on the lower outer periphery of thecore removal bit are disposed in overlapping relation with the dimensionof the formation core that is present within the downwardly facingcentral opening during drilling operations. This feature ensures thatthe formation core is continuously and completely cut away duringdrilling operations even if the dual drill bits should become shiftedlaterally.

The text and drawings set forth above disclose a well drilling mechanismhaving a reamer bit and a core removal bit, both of which rotateclockwise or to the right during wellbore drilling. FIG. 30, however,presents the dual bit well drilling mechanism generally at 270 as havinga reamer bit 271 that is rotated to the right, as is typical forvirtually all deep well drilling systems for discovery and production ofpetroleum products and shows a core removal bit 273 that iscounter-rotated with respect to the rotational direction of the reamerbit. Since the core removal bit is turned to the left, to compensate forthe reaction torque that is developed due to its operation, the threadedconnections of the tubular housing structure of the mud motor 162 mustbe made by right hand threads and the connection of the core removal bitto the bit drive shaft 200 must be made by left hand threads. FIG. 31 isa bottom view showing a duel PDC drill bit generally at 270 which is ofthe same general form as shown in FIG. 8, with the exception that theblade members 272 that are defined by the cutter retention matrix 56 areof more straight configuration as compared to the curved configurationthat is shown in FIG. 8. However, the cutter supporting blade membersextend along the curved path about the bottom and side portions of thematrix material as shown in FIG. 31 The blade members 272 thereforedefine substantially straight cutting edges 274 that define cutterretention receptacles 62 within which the PDC cutter elements 64 areretained.

As is evident in FIGS. 30-32, the reamer bit may be provided with anydesired number of cutter retention blade members 272. As shown in thebottom view of FIG. 30, the reamer bit is shown with four cutterretention blade members while in FIG. 31 the reamer bit is shown withthree equally spaced cutter retention blade members. Thus, it is clearthat the reamer bit may have any desired number of cutter retentionblade members that is suitable for the drilling operation that is to beconducted. In each case, the cutter retention matrix material isconfigured to define a bore or formation core passage 67 that defines adownwardly facing opening 68. The formation core passage 67 isconcentric with respect to the center-line C/L¹ of the tubular housing36 about which the tubular housing 36 is rotated during drillingactivity.

The bore or formation core passage 67 is defined in part by one or morecore gauge protector members 276 that are fixed to the inner endportions of the cutter supporting blades. The gauge protector membersserve to minimize wear of the bore 67 of the reamer bit and minimizeerosive wear of the formation core that is present within the downwardlyfacing opening 68 that is defined by the bore or passage 67. Thisfeature ensures that the formation core within the bore or formationcore passage 67 functions as a gauge member to stabilize rotation of thereamer bit and minimize any lateral movement of the reamer bit withinthe formation during drilling. This feature prevents the wellbore beingdrilled from becoming off gauge during drilling operations. Of course,the formation core is being continuously cut away from the top down asthe reamer bit progresses into the formation. As mentioned above, thetubular housing can be rotated by a rotary drill string or can berotated by a mud motor drive mechanism that is connected with a drillstring that is not rotated continuously for drilling, but may be rotatedfor drill bit orientation, for activities such as for directionaldrilling.

As shown in FIGS. 31 and 32 portion of the reamer bit body 52 and thecutter retention matrix material defines a generally cylindricalinternal wall 278 forming a wall of a bit chamber bit 279 within which acore removal bit 280 is rotated by the operating shaft 200 of the coreremoval bit. The outer, generally cylindrical surface 282 of the coreremoval bit 280 is disposed in spaced relation with the innercylindrical surface 282, thus defining a clearance 284 through whichdrilling fluid flows for cooling and cleaning of the core removal bitafter having flowed through the various fluid passages and channels ofthe bearing pack. After passing through the annular clearance about thecore removal bit, the drilling fluid is discharged into the low pressureregion of the wellbore just below the reamer bit and is then conductedto the surface along with drill cuttings via the annulus between thedrill string 16 and the internal surface that is defined by the wall ofthe wellbore wall. The core removal bit 280, as discussed above isbasically composed of a suitable steel material such as 4140 steel whichmachined and threaded as needed. Tungsten carbide material is then fusedto the steel material and is then coated with PDC material to enhancethe cutting capability and serviceability of the core removal bit. Thecore removal bit defines a cutting face 286 that is oriented for cuttingengagement with the upper end portion of the formation core andcontinuously cuts away the upper portion of the formation core at thesame rate as the reamer bit penetrates into the formation duringwellbore drilling.

The dual drill bits of FIGS. 30 and 31 are cooled and lubricated bydrilling fluid flow in the same manner as discussed above. Drillingfluid passages of the right hand rotatable reamer bit 270 have outlets288 which open to the spaces between the cutter retention blades so thatdrilling fluid is injected into the wellbore in the immediate vicinityof the PDC cutter members 64. If desired, these outlets may becontrolled by flow control nozzle members 142 as discussed above inconnection with FIG. 12 and other FIGS. of the drawings. Drilling fluidof the left hand rotatable core removal bit is also channeled throughflow passages of the central passage 210 of the bit drive shaft 200 anddistributed to the cutting face region of the core removal bit and bitchamber 279 as discussed above in connection with FIG. 15.

It should be noted, concerning FIGS. 30 and 31 that the more centralportions of the cutter retention blades are provided with gaugeprotector members 276. These gauge protectors will be in substantialcontact with the outer cylindrical portion of the formation core toprotect the transverse dimension of the core from being worn, and thusdecreased, by the rotating reamer bit, and also to protect the internaldimension of the reamer bit blades from being worn by its contact withthe core. It is desirable to minimize abrasive wear of the core andreamer bit blades for gauge protection to ensure stabilizing rotation ofthe reamer bit and thus ensure that the wellbore being drilled ismaintained on gauge as precisely as possible.

When the reamer bit has a small core removal bit within a small bitcompartment that is normally rotated to the right, the cutters of thecore removal bit facing to the outside of the reamer bit would be facingthe direction that the reamer is tuning, a cutting position, but cutterson the inside, facing the center of the reamer. The purpose of the coreremoval bit is to cut away the central formation core that the reamerdoes not cut away. If the small core removal bit is designed to berotated to the left, with its cutters facing inwardly, toward the centerof the reamer, the cutters would be moving in the same direction as thereamer, or to the right, an excellent cutting position. To compensatefor the reactive torque that occurs when the cutting face of the coreremoval bit engages the formation core, the core removal bit is mountedto the drive shaft 200 with left hand threads. However, the core removalbit can be rotated to the right but additional rpm's of the core removalbit are required to overcome the reamer speed effect on the small bit. Abit rotation motor that is capable of providing greater rotational speedof the small core removal bit requires a smaller lobe configuration toincrease the speed and requires additional rotor/stator stages toincrease the power that is required to turn the small bit. The motorwould be longer and would require more pressure to operate effectively.If the small bit to the left or counter-rotated, the cutters of the corebit, facing towards the center of the reamer, will be traveling in thesame rotational direction as that of the reamer. It would take lessrpm's on the small bit because the combined rpm's of the reamer andsmall bit would compound. To adjust for the additional rotational speedof the small bit, would require a smaller motor with a larger lobeconfiguration, which means more power and a slower rpm's.

In view of the foregoing it is evident that the present invention is onewell adapted to attain all of the objects and features hereinabove setforth, together with other objects and features which are inherent inthe apparatus disclosed herein.

As will be readily apparent to those skilled in the art, the presentinvention may easily be produced in other specific forms withoutdeparting from its spirit or essential characteristics. The presentembodiment is, therefore, to be considered as merely illustrative andnot restrictive, the scope of the invention being indicated by theclaims rather than the foregoing description, and all changes which comewithin the meaning and range of equivalence of the claims are thereforeintended to be embraced therein.

I claim:
 1. A dual bit well drilling mechanism for drilling attachmentto a tubular well drilling string extending from a drilling rig locatedat the Earth's surface, comprising: a well drilling mechanism beingconnected with the tubular well drilling string and having a connectionbox; a tubular drilling housing having a threaded connection with saidconnection box and defining a fluid flow passage receiving drillingfluid from the tubular well drilling string and defining a housingchamber in communication with said fluid flow passage; a reamer bitbeing connected with said tubular housing and having a multiplicity offormation cutter elements mounted thereto, said reamer bit being rotatedby said well drilling mechanism and defining a formation core receivingreceptacle centrally thereof; a core removal bit chamber being definedby said reamer bit and having communication with said formation corereceiving receptacle; a core removing bit being supported for rotationwithin said core removal bit chamber and having core cutting memberssupported thereby and having a cutting face oriented for engaging andremoving a formation core that remains as said formation cutter elementsof said reamer bit cut a wellbore into the formation, said core removingbit having a reamer bit body and a cutter retention matrix defining aplurality of spaced blade members each having a multiplicity offormation cutter members; and a drilling fluid actuated rotary motorbeing supported by said reamer bit body within said tubular drillinghousing and having rotary driving relation with said core removal bit.2. The dual bit well drilling mechanism of claim 1, comprising: saidcore removal bit receptacle having eccentric relation with saidformation core receiving receptacle; said core removal bit having aplurality of PDC cutter supporting blades defining a cutting face; andsaid reamer bit having a plurality of downwardly extending PDC cuttersupporting blades having inner portions thereof disposed in overlappingrelation with said cutting face of said core removal bit.
 3. The dualbit well drilling mechanism of claim 1, comprising: said reamer bithaving clockwise rotation within the wellbore being drilled; and saidcore removal bit having counter-clockwise rotation within said reamerbit.
 4. The dual bit well drilling mechanism of claim 1, comprising:said drilling fluid actuated rotary motor having a tubular mud motorhousing being supported within said tubular drilling housing by saidreamer bit; a stator member being substantially fixed within saidtubular mud motor housing and defining a substantially helical innerperipheral surface; a rotor member being rotatably supported within saidstator member and having a substantially helical outer peripheralsurface and being rotated by drilling fluid flow between said rotormember and said stator member, said rotor member having a motor outputshaft; a core removal bit drive shaft being in driven relation with saidmotor output shaft, said core removal bit being located at a retractedposition within said reamer bit and having a cutting face exposed tosaid downwardly facing central opening and being mounted to said coreremoval bit drive shaft a bearing pack mechanism being located withinsaid tubular mud motor housing and providing rotary support andstabilization of said core removal bit drive shaft; and said coreremoval bit drive shaft and said bearing pack defining flow passagespermitting flow of drilling fluid therethrough for lubrication andcooling of said bearing pack mechanism and for lubrication and coolingof said core removal bit and for flushing drill cuttings from saidcutting face of said core removal bit.
 5. The dual bit well drillingmechanism of claim 4, comprising: said tubular drilling housing and saiddrilling fluid actuated rotary motor having numerous threadedconnections, said threaded connections of said drilling fluid actuatedrotary motor having left hand threads that resist becoming unthreaded bythe counteracting reactive torque of core removal bit rotation; a rotarycore removal bit drive shaft being driven by said drilling fluidactuated rotary motor; and said core removing bit having right handthreaded connection with said rotary core removal bit drive shaft. 6.The dual bit well drilling mechanism of claim 4, comprising: a centralfluid flow passage being defined by said rotary core removal bit driveshaft; a fluid distribution passage being defined by said core removingcore removal bit and having communication with said central flow passageof said rotary core removal bit drive shaft; and a fluid flow controlnozzle being mounted to said core removing core removal bit andcontrolling the discharge of drilling fluid to said cutting face of saidcore removing bit.
 7. The dual bit well drilling mechanism of claim 1,comprising: a core of formation material being located within saidformation core receiving receptacle of said reamer bit and serving tostabilize said reamer bit during wellbore drilling and providing reamerbit gauge protection minimizing lateral off-gauge movement of saidreamer bit within the formation being drilled; and a plurality of gaugeprotector members being mounted to said reamer bit within said formationcore receiving receptacle and minimizing erosion of the core offormation material and minimizing erosion of said formation corereceiving receptacle during drilling activities and stabilizing saidreamer bit against lateral off-gauge movement within the formationmaterial.
 8. The dual bit well drilling mechanism of claim 1,comprising: said reamer bit defining lateral internal and externalsurfaces having erosive contact with the formation material duringdrilling activity; and a plurality of gauge protector members beingmounted to said lateral internal and external surfaces of said reamerbit and minimizing erosion of said lateral internal and externalsurfaces and minimizing erosion of the formation material duringdrilling activities and thus stabilizing said reamer bit during drillingand minimizing gauge enlarging movement of said reamer bit within theformation.
 9. The dual bit well drilling mechanism of claim 1,comprising: a drilling fluid inlet passage being defined by said tubulardrilling housing; a high pressure fluid flow chamber being definedwithin said tubular drilling housing and externally of said drillingfluid actuated rotary motor; and a fluid inlet fitting defining an upperportion of said drilling fluid actuated rotary motor and defining amotor actuation passage, said fluid inlet fitting permitting apredetermined flow of drilling fluid from said high pressure fluid flowchamber through said drilling fluid actuated rotary motor for coreremoval bit rotation, for cooling lubrication and flushing of drillcuttings from said core removing bit.
 10. The dual bit well drillingmechanism of claim 1, comprising: a core removal bit bore being definedby said reamer bit body and being disposed in eccentric relation withsaid formation core receiving receptacle; and said core removing bitbeing positioned for rotation within said core removal bit bore andhaving said cutting face oriented for substantially continuous cuttingengagement with the formation core as said formation cutter elements ofsaid reamer bit body penetrate into the formation being drilled.
 11. Thedual bit well drilling mechanism of claim 1, comprising: a core removalbit bore being defined by said reamer bit body and being disposed inconcentric relation with said formation core receiving receptacle; andsaid core removing bit being positioned for rotation within said coreremoval bit bore and having said cutting face oriented for substantiallycontinuous cutting engagement with the formation core as said formationcutter elements of said reamer bit body penetrate into the formationbeing drilled.
 12. The dual bit well drilling mechanism of claim 1,comprising: said reamer bit having a reamer bit body mounted to saidtubular drilling housing; a cutter retention matrix being adhered tosaid reamer bit body and defining bit outer periphery and a formationcore receiving receptacle, said cutter retention matrix defining aplurality of cutter retention blades extending from said bit outerperiphery to said formation core receiving receptacle; a multiplicity ofPDC cutter elements being mounted to said cutter retention blades anddefining a reamer bit cutter array; and said core removing bit havingdriven relation with said rotor member and being positioned within saidformation core receiving receptacle for core removing engagement withthe formation core.
 13. A dual bit well drilling mechanism for drillingattachment to a tubular well drilling string extending from a drillingrig located at the Earth's surface, comprising: a tubular drillinghousing having a threaded connection with said well drilling string anddefining a fluid flow passage receiving drilling fluid from the tubularwell drilling string and defining a housing chamber in communicationwith said fluid flow passage; a stator member being mounted insubstantially fixed and sealed relation within said tubular drillinghousing and defining a generally helical internal fluid flow reactionprofile; a rotor member being rotatably positioned within said statormember and having a generally helical external fluid flow reactionprofile for fluid flow responsive rotation of said rotor member bydrilling fluid flow, said rotor member defining a central passagetherethrough and defining an open end; a reamer bit being defined bysaid tubular drilling housing and having a multiplicity of formationcutter elements mounted thereto, said tubular drilling housing and saidreamer bit being rotated by said well drilling mechanism and defining aformation core receiving receptacle centrally thereof; a core removalbit chamber being defined by said reamer bit body and being exposed tosaid formation core receiving receptacle; and a core removing bit beingsupported for rotation within said core removal bit chamber and havingrotary driven relation with said rotor member, a plurality of coreremoval members supported thereby, said core removing bit having acutting face oriented for engaging and removing a formation core thatremains as said formation cutter elements of said reamer bit body cut awellbore into the formation.
 14. The dual bit well drilling mechanism ofclaim 13, comprising: said rotor driven shaft being flexible andabsorbing rotary shock forces transmitted there to by said rotor memberand minimizing rotary shock forces being transmitted to said coreremoval bit operating shaft and to said core removal bit.
 15. The dualbit well drilling mechanism of claim 13, comprising: said reamer bithaving a reamer bit body mounted to said tubular drilling housing; acutter retention matrix being adhered to said reamer bit body anddefining bit outer periphery and a formation core receiving receptacle,said cutter retention matrix defining a plurality of cutter retentionblades extending from said bit outer periphery to said formation corereceiving receptacle; a multiplicity of PDC cutter elements beingmounted to said cutter retention blades and defining a reamer bit cutterarray; and said core removing bit having driven relation with said rotormember and being positioned within said formation core receivingreceptacle for core removing engagement with the formation core.
 16. Thedual bit well drilling mechanism of claim 13, comprising: a bearing packbeing mounted to said reamer bit body a shaft being rotated by saidrotor member and having a portion thereof located within said centralpassage of said rotor member; a core removal bit operating shaftextending through said bearing pack and having driven connection withsaid rotor driven shaft and having driving connection with said coreremoving bit.
 17. The dual bit well drilling mechanism of claim 16,comprising: said bearing pack defining drilling fluid flow passagespermitting flow of drilling fluid therethrough for cooling andlubricating said bearing pack, for cooling of said core removing bit andfor flushing away drill cuttings from said core removing bit.
 18. Amethod for drilling wells in consolidated earth formations, comprising:rotating in formation cutting engagement with an earth formation adrilling mechanism having a tubular drilling housing and a reamer bitconnected with said tubular drilling housing, said reamer bit defining acutting face and defining a downwardly facing core receiving receptaclewithin which a substantially cylindrical formation core left by saidreamer bit is received during drilling; rotating a core removal bitwithin said reamer bit with a drilling fluid energized rotary motorhaving a tubular motor housing supported within said tubular drillinghousing by said reamer bit, said core removal bit having a core cuttingface exposed to said downwardly facing core receiving receptacle and incutting engagement with a circular end of the substantially cylindricalformation core and having a retracted position within said reamer bitwith its core cutting face offset from said cutting face of said reamerbit, said retracted position determining the length of the substantiallycylindrical formation core; conducting drilling fluid flow through saiddrilling fluid energized rotary motor, through a bearing pack withinsaid drilling fluid energized rotary motor and through said coreremovable bit; and discharging drilling fluid from said core removablebit into said downwardly facing core receiving receptacle at saidcutting face of said core removal bit.
 19. The method of claims 18,comprising: engaging a generally cylindrical surface of the formationcore within said downwardly facing core receiving receptacle by gaugeprotection members supported by said reamer bit internally of saiddownwardly facing core receiving receptacle and minimizing erosive wearof the formation core; and utilizing the formation core to stabilizerotation and positioning of said reamer bit during drilling andmaintaining the guage and orientation of the wellbore being drilled. 20.The method of claim 19, comprising: controlling the flow of drillingfluid through said drilling fluid energized rotary motor and throughflow passages of said bearing pack and core removing bit for cooling,lubrication thereof and for flushing away drill cuttings from said coreremoving bit.